scholarly journals The Parabolic Variational Inequalities for Variably Saturated Water Flow in Heterogeneous Fracture Networks

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-16 ◽  
Author(s):  
Zuyang Ye ◽  
Qinghui Jiang ◽  
Chi Yao ◽  
Yanzhang Liu ◽  
Aiping Cheng ◽  
...  
Keyword(s):  
Water Flow ◽  
Seepage Flow ◽  
Fracture Networks ◽  
Flow Process ◽  
Water Seepage ◽  
Matrix Permeability ◽  
Saturated Water ◽  
Fracture Systems ◽  
The Matrix ◽  
Fracture Distribution

Fractures are ubiquitous in geological formations and have a substantial influence on water seepage flow in unsaturated fractured rocks. While the matrix permeability is small enough to be ignored during the partially saturated flow process, water seepage in heterogeneous fracture systems may occur in a non-volume-average manner as distinguished from a macroscale continuum model. This paper presents a systematic numerical method which aims to provide a better understanding of the effect of fracture distribution on the water seepage behavior in such media. Based on the partial differential equation (PDE) formulations with a Signorini-type complementary condition on the variably saturated water flow in heterogeneous fracture networks, the equivalent parabolic variational inequality (PVI) formulations are proposed and the related numerical algorithm in the context of the finite element scheme is established. With the application to the continuum porous media, the results of the numerical simulation for one-dimensional infiltration fracture are compared to the analytical solutions and good agreements are obtained. From the application to intricate fracture systems, it is found that water seepage flow can move rapidly along preferential pathways in a nonuniform fashion and the variably saturated seepage behavior is intimately related to the geometrical characteristics orientation of fractures.

Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

2013 ◽  
Author(s):  
Hannes Hofmann ◽  
Tayfun Babadagli ◽  
Günter Zimmermann
Keyword(s):  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Networks ◽  
Network Development ◽  
Complex Fracture ◽  
Fracture Patterns ◽  
Fracture Systems ◽  
Fracture Development ◽  
Complex Fracture Network ◽  
Treatment Designs

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and Hot-Dry-Rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in bi-wing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial Discrete Fracture Network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulation results reveal valuable information about main parameters influencing fracture network properties, major factors leading to complex fracture network development, and differences between HDR and shale gas/oil shale stimulations.

Allocation of fracturing intervals and justification of fracture parameters in the pre-Jurassic deposits

2021 ◽  
pp. 9-19
Author(s):  
P. A. Boronin ◽  
N. V. Gilmanova ◽  
N. Yu. Moskalenko
Keyword(s):  
Permeability Coefficient ◽  
Complex Structure ◽  
High Flow ◽  
Well Testing ◽  
Rock Matrix ◽  
Unconventional Reservoir ◽  
Flow Rates ◽  
Matrix Permeability ◽  
The Matrix ◽  
Standard Set

The object of research in this article is the productive deposits of the pre-Jurassic complex. The pre-Jurassic complex is of great interest, this is an unconventional reservoir with a complex structure and developed fractured zones. High flow rates cannot be determined by the rock matrix, since the matrix permeability coefficient is on average 2−3 md. In this regard, there is the problem of separation of fractured intervals according to a standard set of well testing.

A Novel Coreflood Test to Evaluate EOR Potential of Wettability-Altering Surfactants in Oil-Wet Heterogeneous Carbonate Reservoirs

2021 ◽  
Author(s):  
Yue Shi ◽  
Kishore Mohanty ◽  
Manmath Panda
Keyword(s):  
Oil Recovery ◽  
Carbonate Reservoirs ◽  
Wettability Alteration ◽  
Low Permeability ◽  
High Permeability ◽  
Matrix Permeability ◽  
Rock Heterogeneity ◽  
The Matrix ◽  
Flow Through ◽  
Main Factors

Abstract Oil-wetness and heterogeneity (i.e., existence of low and high permeability regions) are two main factors that result in low oil recovery by waterflood in carbonate reservoirs. The injected water is likely to flow through high permeability regions and bypass the oil in low permeability matrix. In this study, systematic coreflood tests were carried out in both "homogeneous" cores and "heterogeneous" cores. The heterogeneous coreflood test was proposed to model the heterogeneity of carbonate reservoirs, bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. The results of homogeneous coreflood tests showed that both secondary-waterflood and secondary-surfactant flood can achieve high oil recovery (>50%) from relatively homogenous cores. A shut-in phase after the surfactant injection resulted in an additional oil recovery, which suggests enough time should be allowed while using surfactants for wettability alteration. The core with a higher extent of heterogeneity produced lower oil recovery to waterflood in the coreflood tests. Final oil recovery from the matrix depends on matrix permeability as well as the rock heterogeneity. The results of heterogeneous coreflood tests showed that a slow surfactant injection (dynamic imbibition) can significantly improve the oil recovery if the oil-wet reservoir is not well-swept.

Exploring Low-IFT Foam EOR in Fractured Carbonates: Success and Particular Challenges of Sub-10-md Limestone

SPE Journal ◽  
1900 ◽  
Vol 25 (02) ◽  
pp. 867-882
Author(s):  
Pengfei Dong ◽  
Maura Puerto ◽  
Guoqing Jian ◽  
Kun Ma ◽  
Khalid Mateen ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Surfactant Solution ◽  
Mineral Dissolution ◽  
Mobility Control ◽  
Matrix Permeability ◽  
Geochemical Properties ◽  
Remaining Oil ◽  
The Matrix ◽  
Incremental Oil Recovery ◽  
Foam Flooding

Summary The high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-md formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions. The low-IFT foam process was investigated through coreflood experiments in homogeneous and fractured oil-wet cores with sub-10-md matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer [alpha olefin sulfonate (AOS) C14-16] were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the coreflood experiments. Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-md matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-md matrix permeability achieved 64% incremental oil recovery compared to waterflooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, the foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluid flow in the matrix. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of the low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids—such as mineral dissolution and the exchange of calcium and magnesium—were found to increase the Ca2+ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca2+ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It, therefore, may cause injectivity and phase-trapping issues especially in the homogeneous limestone. Results in this work demonstrated that despite the challenges associated with limestone dissolution, the low-IFT foam process can remarkably extend chemical enhanced oil recovery (EOR) in fractured oil-wet tight reservoirs with matrix permeability as low as 5 md.

scholarly journals Improved Method for Measuring the Permeability of Nanoporous Material and Its Application to Shale Matrix with Ultra-Low Permeability

Materials ◽  
2019 ◽  
Vol 12 (9) ◽  
pp. 1567 ◽  
Author(s):  
Taojie Lu ◽  
Ruina Xu ◽  
Bo Zhou ◽  
Yichuan Wang ◽  
Fuzhen Zhang ◽  
...  
Keyword(s):  
High Pressure ◽  
Fluid Transport ◽  
Effective Means ◽  
Clean Energy ◽  
Nanoporous Materials ◽  
Environmental Research ◽  
Low Permeability ◽  
Matrix Permeability ◽  
Wide Range ◽  
The Matrix

Nanoporous materials have a wide range of applications in clean energy and environmental research. The permeability of nanoporous materials is low, which affects the fluid transport behavior inside the nanopores and thus also affects the performance of technologies based on such materials. For example, during the development of shale gas resources, the permeability of the shale matrix is normally lower than 10−3 mD and has an important influence on rock parameters. It is challenging to measure small pressure changes accurately under high pressure. Although the pressure decay method provides an effective means for the measurement of low permeability, most apparatuses and experiments have difficulty measuring permeability in high pressure conditions over 1.38 MPa. Here, we propose an improved experimental method for the measurement of low permeability. To overcome the challenge of measuring small changes in pressure at high pressure, a pressure difference sensor is used. By improving the constant temperature accuracy and reducing the helium leakage rate, we measure shale matrix permeabilities ranging from 0.05 to 2 nD at pore pressures of up to 8 MPa, with good repeatability and sample mass irrelevance. The results show that porosity, pore pressure, and moisture conditions influence the matrix permeability. The permeability of moist shale is lower than that of dry shale, since water blocks some of the nanopores.

The Influence of Drying and Stress on the Permeability of Texas Lignite

1977 ◽  
Vol 99 (4) ◽  
pp. 634-640
Author(s):  
T. W. Thompson ◽  
S. Sen ◽  
K. E. Gray ◽  
T. F. Edgar
Keyword(s):  
Applied Stress ◽  
Significant Influence ◽  
Confining Pressure ◽  
Fracture Permeability ◽  
Gasification Process ◽  
Matrix Permeability ◽  
The Matrix ◽  
Order Of Magnitude ◽  
Permeability Increase

Tests have been carried out to quantify the variation in permeability of Texas lignite with drying and with applied stress. It has been shown that the matrix permeability of lignite may be increased from effectively zero to the order of 10 darcies by removing about 20 percent by weight of water. In addition, an increase of confining pressure after drying will reduce the permeability, but only by about one order of magnitude. Drying of the matrix thus may produce matrix permeabilities of the same order as the undried field fracture permeability. The permeability increase of the matrix is initially greater parallel to the bedding than perpendicular, but after further drying the two orientations show similar final permeabilities. This drying effect could have a significant influence on the operation of an in-situ gasification process by increasing the transmissivity and injectivity of the producing seam. Drying of the seam could occur by the flow of unsaturated gas and will be enhanced by combustion.

scholarly journals Effects of oil field brine wastewater on saturated hydraulic conductivity of smectitic loam soils

2016 ◽  
Vol 96 (4) ◽  
pp. 496-503 ◽  
Author(s):  
Nathan E. Derby ◽  
Francis X.M. Casey ◽  
Thomas M. DeSutter
Keyword(s):  
Hydraulic Conductivity ◽  
Water Flow ◽  
Great Plains ◽  
Crop Production ◽  
Saturated Hydraulic Conductivity ◽  
Oil Field ◽  
Oil Well ◽  
High Sodium ◽  
Saturated Water ◽  
Western North Dakota

Spills of brine wastewater produced during oil well drilling are occurring more frequently in the Great Plains, resulting in crop production loss on affected soil. Remediation requires removal of salt from the topsoil, which might be accomplished by leaching to subsurface horizons or subsurface drains. A laboratory study determined the effects of brine on saturated hydraulic conductivity (Ks) of four nonimpacted surface soils from western North Dakota, USA. Repacked soil cores were subjected to saturated water flow, followed by one pore volume of brine. Subsequent saturated water flow leached brine from the soil and reduced Ks as much as 97% (0.086–0.003 cm h−1) within 24 h. Effluent total dissolved solids (TDS) approached 250 000 mg L−1 then declined (5 mg L−1) with continued leaching, but Ks did not increase. Removal of soluble salts during leaching increased the relative sodium concentrations (ESP > 55), causing clay swelling/dispersion and reduced Ks. Postbrine gypsum application (11.2 Mg ha−1) to replace exchangeable sodium with calcium did not improve Ks. This evidence suggests that if subsurface drainage is used for reclaiming brine-impacted soils that special attention be given to where dispersion/swelling is occurring, leaching water quality, and closely positioning calcium amendments within the high sodium zones.

Micro-scale simulation of bubble-water flow in coal seams by the lattice Boltzmann method

2016 ◽  
Vol 56 (2) ◽  
pp. 608
Author(s):  
Jie Yi ◽  
Huilin Xing ◽  
Tianwei Sun ◽  
Victor Rudolph
Keyword(s):  
Coal Seam ◽  
Water Flow ◽  
Flow Rate ◽  
Bubble Size ◽  
Lattice Boltzmann ◽  
Water Flow Rate ◽  
Bubble Flow ◽  
Coal Seam Gas ◽  
Two Phase ◽  
Flow Process

The production of coal seam gas initially requires pumping and removing significant amounts of water to sufficiently reduce the hydrostatic pressure in the subsurface, so that methane can desorb from the matrix and diffuse into the cleat systems; majority of the methane molecules gather into nucleation or bubbles. During the depression, the flow pattern of gas in cleats changes from bubble flow to slug flow, and finally forms circular flow. The significance of the bubble flow process—during which the liquid phase is continuous while the gas phase exists as small bubbles randomly distributed within the liquid—has not been emphasised because of its complexity. In this study, a free energy based two-phase lattice Boltzmann model is used to simulate the gas bubble/water flow behaviour in micro-cleats of a coal seam gas reservoir. The model was validated by comparison with analytical results based on dimensionless numbers, and good agreement was found in general. The influences of bubble shape, bubble size, and coal surface wettability on gas water two-phase flow in micro-cleats are discussed. The simulation results indicate that the bubble size and wettability of gas have significant impacts on the flow capacity of both gas and water. A decrease of the water flow rate is observed when large bubbles occur, and the gas flow rate decreases when the gas wettability becomes stronger. The bubble flow process significantly influences the drainage of water and the further gas production.

scholarly journals Water Intrusion Characterization in Naturally Fractured Gas Reservoir Based on Spatial DFN Connectivity Analysis

Energies ◽  
2020 ◽  
Vol 13 (16) ◽  
pp. 4235
Author(s):  
Pengyu Chen ◽  
Mauricio Fiallos-Torres ◽  
Yuzhong Xing ◽  
Wei Yu ◽  
Chunqiu Guo ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Water Flow ◽  
Fracture Network ◽  
Connectivity Analysis ◽  
Fracture Networks ◽  
Flow Paths ◽  
Water Intrusion ◽  
Discrete Fracture ◽  
Single Well ◽  
Water Flow Paths

In this study, the non-intrusive embedded discrete fracture model (EDFM) in combination with the Oda method are employed to characterize natural fracture networks fast and accurately, by identifying the dominant water flow paths through spatial connectivity analysis. The purpose of this study is to present a successful field case application in which a novel workflow integrates field data, discrete fracture network (DFN), and production analysis with spatial fracture connectivity analysis to characterize dominant flow paths for water intrusion in a field-scale numerical simulation. Initially, the water intrusion of single-well sector models was history matched. Then, resulting parameters of the single-well models were incorporated into the full field model, and the pressure and water breakthrough of all the producing wells were matched. Finally, forecast results were evaluated. Consequently, one of the findings is that wellbore connectivity to the fracture network has a considerable effect on characterizing the water intrusion in fractured gas reservoirs. Additionally, dominant water flow paths within the fracture network, easily modeled by EDFM as effective fracture zones, aid in understanding and predicting the water intrusion phenomena. Therefore, fracture clustering as shortest paths from the water contacts to the wellbore endorses the results of the numerical simulation. Finally, matching the breakthrough time depends on merging responses from multiple dominant water flow paths within the distributions of the fracture network. The conclusions of this investigation are crucial to field modeling and the decision-making process of well operation by anticipating water intrusion behavior through probable flow paths within the fracture networks.

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